Calpine Corporation reported third quarter 2008 earnings results. Key highlights included record operating revenues of $3.2 billion, a 37% increase over third quarter 2007. Adjusted EBITDA was a record $593 million, a 17% increase. Cash flow from operations was also a record at $941 million. The company achieved excellent operational performance during the quarter despite hurricanes. Calpine provided guidance for full-year 2008 adjusted EBITDA of $1.65-1.675 billion and discussed near-term strategies around hedging, operations excellence, and growth opportunities.

1. CALPINE CORPORATION
Third Quarter 2008
Earnings Results
November 7, 2008

2. Safe Harbor Statement
Forward-Looking Statements
The information contained in this presentation includes certain estimates, projections and other forward-looking
information that reflect Calpine’s current views with respect to future events and financial performance. These estimates,
projections and other forward-looking information are based on assumptions that Calpine believes, as of the date hereof,
are reasonable. Inevitably, there will be differences between such estimates and actual results, and those differences may
be material.
There can be no assurance that any estimates, projections or forward-looking information will be realized.
All such estimates, projections and forward-looking information speak only as of the date hereof. Calpine undertakes no
duty to update or revise the information contained herein.
You are cautioned not to place undue reliance on the estimates, projections and other forward-looking information in this
presentation as they are based on current expectations and general assumptions and are subject to various risks,
uncertainties and other factors, including those set forth in Calpine’s Form 10-K for the fiscal year ended December 31,
2007, Calpine’s Quarterly Reports filed on Form 10-Q for the periods ended March 31, 2008, June 30, 2008, and September
30, 2008, and in other documents that Calpine files with the SEC. Many of these risks, uncertainties and other factors are
beyond Calpine’s control and may cause actual results to differ materially from the views, beliefs and estimates expressed
herein. Calpine’s reports and other information filed with the SEC, including the risk factors identified in its Annual Report
on Form 10-K for the year ended December 31, 2007, and in its Quarterly Reports on Form 10-Q for the periods ended March
31, 2008, June 30, 2008, and September 30, 3008, can be found on the SEC’s website at www.sec.gov and on Calpine’s
website at www.calpine.com.
Reconciliation to GAAP Financial Information
The following presentation includes certain “non-GAAP financial measures” as defined in Regulation G under the Securities
Exchange Act of 1934. A schedule is attached hereto that reconciles the non-GAAP financial measures included in the
following presentation to the most directly comparable financial measures calculated and presented in accordance with
Generally Accepted Accounting Principles.
1

3. Executive Team & Agenda
Calpine Executive Team
Jack Fusco Thad Hill Zamir Rauf Thad Miller
President & CEO EVP & CCO Interim EVP & CFO EVP, CLO & Secretary
11-yr career in Power
25-yr career in Power 17-yr financial career, 30-yr legal career,
Industry
Industry including 12 years including 20 years
in Power Industry in Power Industry
• Hedging Strategy
• Core Initiatives • Financial Results • Available for Q&A
• Operations Overview
3rd Quarter Highlights
• • Liquidity & Debt
• Calpine Market Views
• Expected Results • Guidance
2

4. Current Announcements
Proud to be a Calpine Employee
Excellent performance following Hurricane Ike
- ERCOT recognizes Calpine’s Texas fleet for outstanding plant availability of 97%
- Commercial operations performance was exceptional
- Business continuity was seamless
Excellent performance during financial crisis
- Effectively managed commodity price risk & volatility
- Continuous analysis of counterparty credit risk & proactive management of
financial exposures
- Conservative balance sheet management to help navigate through uncharted
waters
Expect continued conservative approach on how we manage the operational
and financial aspects of our business
3

5. Near-Term Strategy
Be the Premier Independent Power Provider
Be the Premier Independent Power Provider
Run the Business
Core Near-Term
Initiatives
• First-tier Operational Results
Expected Results
• Consistent Financial Results
• Proactive Risk Management
• Retain And Attract Skilled
Employees
• Excellence In Operations
• Optimize Existing Assets • Business Transparency
• Expand Our Portfolio Of • Annual Financial Guidance
Power Generation Facilities
• Improved Investment
• Leverage Our Expertise In Decisions
Geothermal Operations
• Stronger Balance Sheet
• Improving Return On Capital
4

6. Core Near-Term Initiatives
1. Retain and Attract Skilled Employees
• Hired Thad Miller, Thad Hill, as well as, key positions throughout all levels of the Company
• Reduced reliance on 3rd parties
• Developing commercial analytics organization to create Calpine “view”
2. Excellence in Operations
• “100-Day Plan” in place to address critical items
• Improved safety and reliability statistics for the quarter but need to maintain progress
throughout the year
• Began streamlining processes and procedures to increase organizational effectiveness
• Achieving Calpine Excellence
3. Optimize Existing Assets
• Funding aggressive major maintenance initiatives
• Investing in upgrades that add capacity to our existing facilities
• Implementing new approach to hedging to increase levels out 2-3 years
4. Expand our Portfolio of Power Generation Facilities
• Completed Greenfield Energy Centre
• Otay Mesa on schedule for COD in 3rd Quarter 2009
• Shortlisted on request for proposals for 650 MW to 1200 MW of capacity and energy
5. Leverage our Expertise in Geothermal Operations
• Continuing five-year investment program to maintain capacity at The Geysers
5

7. Third Quarter 2008 Operations Results
Safe • Top quartile safety performance achieved
Safe 1
Lost-time incident rate of 0.17
Scale
2
• Significant power produced with over 25.9 million MWh
Scale • Significant steam produced 12.7 billion lbs
• Best-in-class performance with 61 natural gas plants, out of 78, that
had a >95% Availability Factor
• The Geysers Forced Outage Factor Rate 0.01% and corresponding
Reliable capacity factor of 93.9%
Reliable
• Gas plant Forced Outage Factor of 2.8%
Forced Outage Factor <2% without Hurricanes Ike & Gustav
• Peaking units had a 98% Starting Reliability
Efficient • Operating Heat Rate of 7,274 Btu/KWh
Efficient
1 based on 2006 NAICS 221112 – Fossil Fuel Electric Power Generation 1,000+ Employees
2 Not Adjusted for Unconsolidated Investments
6

8. Balanced Dispatch Characteristics
3rd Quarter 2008 Net Capacity Factors
12
11% NCF
Dispatchable Heat Rates (mmbtu/MWh)
94% NCF
9
60% NCF
95% NCF
6
3
Intermediate
Baseload Peaking
0
23,699 MW 1
0
Calpine Installed Capacity (MW)
Geothermal Cogeneration Combined Cycle Peaking
Geothermal units have essentially no fuel input; therefore heat rate values
for Geothermal are for comparative purposes only.
1Installed Capacity as of 9/30/2008
Note: NCF= Net Capacity Factor
7

9. Third Quarter 2008 Financial Results
Operating Revenues
37%
$3,190
• Operating Revenues of $3.2 billion
$2,324
- Record 37% increase over 3Q07
• Record Commodity Margin of $842 million
3Q07 3Q08
Commodity Margin
- 15% increase over 3Q07
15%
• Record Adjusted EBITDA of $593 million
- 17% increase over 3Q07
$842
$732
• Record Cash Flow from Operations of $941 million
3Q07 3Q08
• Corporate liquidity Of $1.6 billion and growing
Adjusted EBITDA
17%
$593
$505
3Q07 3Q08
8

10. What Can Investors Expect From Calpine?
Full-Year 2008 Adjusted
Full-Year 2008 Adjusted
$1,650 - 1,675 million
EBITDA guidance
EBITDA guidance
When
Expected Results
Expected Results
No later than
No later than
2009 Guidance
2008 Q4 Earnings Call
•• Better understanding of 2008 Q4 Earnings Call
Better understanding of
our business and
our business and
increased transparency
increased transparency
•• Clear capital allocation
Clear capital allocation
program
program
•• Outline of growth
Outline of growth
opportunities
opportunities
•• Increased regulatory
Increased regulatory
focus Spring 2009 Analyst Day
focus Spring 2009 Analyst Day
Other March 31, 2009
March 31, 2009
9

11. OPERATIONS UPDATE
10

12. Third Quarter Operation’s Highlights
Plant Operations’ Achievements
Excellence in safety: Far exceeding top-quartile safety performance
Lost-time incident rate of 0.17
Excellence in Geothermal: The Geysers with only a 0.01% Forced Outage Factor
Excellence in Fossil Generation: Forced Outage Factor of less than 2% after storm adjustments
2.8% before adjustments for storms
Commercial Operations’ Achievements
Substantially increased hedges in difficult commercial environment for 2009 at targeted prices
Strong position to weather current economic slowdown
Well positioned for economic recovery
Focus on collateral efficiency: Increased usage of first lien program
Accounts for 15% of our portfolio hedges outstanding vs. 9% last quarter
Increased usage by almost 140% in the last 60 Days
Excellence in Commercial Management: Texas team delivered strong September results despite
Hurricane Ike
Growth Achievements
Greenfield Energy Centre achieved COD on October 17, 2008
11

13. Operations Overview
2
Employee Lost-Time Incident Rate Generation in Key Markets (000 MWh)
0.5
9,907 9,830
0.42
9,059
8,653
0.31 0.31
5,089
0.20
0.17 3,806
0.13
1,913 1,669
1,565 1,504
2003 2004 2005 2006 2007 YTD08 West - Gas West - Geo Texas Southeast North
3Q07 3Q08
1
Calpine BLS 2006 1st Quartile
Forced Outage Factor (%) Plants with no recordable injuries and <0.5%
7.23
Forced Outage Factor
1.98 w/o
1.28 w/o 0.50 w/o
hurricane
hurricane hurricane
Auburndale Goose Haven Peaker Oneta
4.55
Agnews Greenleaf Cogen Pine Bluff
3.94
3.85
Blue Spruce Hermiston Riverside
2.52 2.80
2.58 Channel Hog Bayou Riverview Peaker
2.48
2.19
Clear Lake Los Medanos Rocky Mountain
Creed Peaker Mankato Watsonville
0.68
0.04 Decatur Metcalf Yuba City Peaker
0.01
Feather River Peaker Morgan Zion
West - Gas West - Geo Texas Southeast North CPN Gilroy Peakers
3Q07 3Q08
1 NAICS 221112 – Fossil Fuel Electric Power Generation 1,000+ Employees
2 Excludes plants sold or mothballed since 3Q07 (Adjusted for sale of Acadia and mothball of Pryor). Not adjusted for deconsolidation of Auburndale and RockGen
12

14. Near-Term Hedging Approach
Focus
Focus Asset optimization, not trading
Current Year
Current Year “Close-out” 2008 positions
Recognizing difficult market and uncertain outlook……
Reduce exposure for 2009 at attractive, relative pricing
Future Years
Future Years Partially hedged for 2010 to protect against severe downside
Leave room for acceleration out of recession
Look longer-term to take opportunistic advantage of market volatility
Investors
Investors Increased transparency without harming commercial prospects
Collateral Increase usage of Calpine First-Lien to support hedging and conserve cash
Collateral collateral
13

15. Energy Margin Hedge Profile
Energy Margin Includes:
1
Energy Hedge Profile
•Electricity Sales
•Steam Margin
8%
•Ancillary Services 26%
52%
65%
92%
74%
48%
Energy 35%
Margin
90%
2
2008 2009 2010 2011
Regulatory
3 3
Hedged Volume Open Volume
Capacity +
Renewables
10%
4
Hedged Spark Spread Price 2008 2009 2010 2011
($/MWh) $26 $27 $28 $35
Forecast (MW)5 23,699 24,202 24,798 24,798
1 As of portfolio valuation on 10/31/08.
2 2008 values are for balance of year.
3 Volumes are on a delta hedge basis. Delta volumes are the expected volume based on the probability of economic dispatch at a future date based on
current market prices for that future date. This is typically lower than the notional volume, which is plant capacity, less known performance and
operating constraints.
4 Prices are for the entire calendar year in 2008. Actuals through quarter ending 9/30/08 and hedged through 12/31/08
5 Represents Calpine’s forecasted net ownership interest with peaking capacity
14

16. Adjusted EBITDA Sensitivities
Market Heat Rate Sensitivity ($mm)
Natural Gas Pric e Sensitivity ($mm) $200
$200
$150
$150
$100
Change to Adjusted EBITDA
$100
Change to Adjusted EBITDA
182
141 $50
77
$50 91
43
$0
28
$0
(40)
(30) (73) (89)
($50)
($50)
(148)
(180) ($100)
($100)
($150)
($150)
($200)
($200)
2009 2010 2011
2009 2010 2011
Heat Rate +.17 mmbtu/MWh Heat Rate -.17 mmbtu/MWh
Natural Gas +$1/mmbtu Natural Gas -$1/mmbtu
15

17. Fixed Payment Hedge Profile
Regulatory Capacity + Renewables Includes:
Capacity Payments1
•
• Renewable Energy Credits
Hedged Regulatory Capacity and Renewable Payments
• Resource Adequacy / RMR
21% 23% 23%
Energy
79% 77% 77% Margin
90%
Regulatory
Capacity +
Renewables
2009 2010 2011 10%
Hedged Dollars Unhedged Dollars
1 Capacity Payments include Regulatory Capacity Payments, but exclude capacity payments associated with PPA’s, ESA’s or tolling agreements
Note: Annual Commodity Margin portion is based on 2009 Estimate. Hedged Data as of 10/31/2008
16

18. First Lien Program and Counterparty Risk Overview
First-lien Growing & Accelerating Strong credit profile of counterparties3
3
Percentage of net exposure
1%
First-lien usage 8/31 to present1
.3%
%.
2
Increased MW’s in first-lien program 139%
13%
First-lien as % of total new hedges 46%
(note 58% since mid-September) 86%
First-lien as a % of total hedges 15%
(up from 11%)
Investment Grade
Government / ISO's
Below Investment Grade
Not Rated
1 For Calendar year 2009 and 2010
2 And equivalents
3 CES contracts do not include plant specific contracts like host steam and power
17

19. Growth Opportunities
Greenfield Energy Centre (COD of Oct. 17, 2008)
- 1,005 MW gas-fired facility
- 50% owned (partnership with Mitsui)
Greenfield Energy Centre, October 2008
Otay Mesa Energy Center (projected Q3 2009 COD)
- 596 MW combined-cycle plant, 100% owned
- Setting completed for HRSG modules & Unit 1&2 stacks;
Completed major foundations
Russell City (possible 2012 COD)
Otay Mesa Energy Center, October 2008
- 600 MW combined-cycle plant, 65% owned (partnership with GE)
- Executed PPA before the CPUC
- Permitting in process
Multiple long-term PPAs in discussions
Ongoing evaluation of additional opportunities
Ongoing evaluation of additional opportunities
for disciplined growth
for disciplined growth
18

20. Calpine Views on Current Market Concerns
Recession Substantially hedged 2009, good progress on 2010
Current state of credit markets have effectively slowed new builds
Market For our hedging window, some liquidity loss, but hedging progress
Liquidity continues
Wind In Texas, slower roll-out of CREZ
More regulatory review to come – especially around capacity and
ancillaries
One view: higher on-peak and lower off-peak
Lower Gas Volatility not decreasing
Prices Investment slowdown bullish in medium term
Our Credit Plenty of cash liquidity
First-lien hedging program healthy
19

21. FINANCIAL UPDATE
20

22. Long-Term Financial Strategy
Strengthen balance sheet
- Cash generation through prudent risk management and
Strengthen
Strengthen reduction of expenses
- Maintain strong liquidity and focus on non cash collateral
alternatives
Simplify capital structure
- Refinance project debt at corporate level
Simplify - Free trapped cash
Simplify - Increase transparency
- Reduce debt
Fiscally responsible
- Disciplined capital allocation
Responsible - Fund attractive growth projects to increase return on
Responsible equity
21

23. Summary Financial Results
Commodity Margin ($mm)
Third Quarter Highlights:
Revenues increased by 37%
$2,113
Commodity Margin ↑ 15% & Adjusted EBITDA ↑ 17% from 3Q 2007
⇒ Higher spark spreads & effective risk management in
$1,689
Texas
⇒ New/renegotiated contracts in West & Southeast
$842
$732
Year-to-date Highlights:
Revenues increased by 32%
Commodity Margin ↑ 25% & Adjusted EBITDA ↑ 26% compared to
2007
3Q07 3Q08 YTD07 YTD08
⇒ Increased spark spreads in Texas & West
Adjusted EBITDA ($mm)
Strong Liquidity of $1.6 billion ↑ 135% for the quarter
$1,361
Sufficient to cover debt maturities through 2009
$1,081
Improved the quality of liquidity
Increased focus on first-lien hedging program
$593
$505
3Q07 3Q08 YTD07 YTD08
22

24. Third Quarter 2008 vs 2007 Adjusted EBITDA Bridge
$106
Exceptional $(26)
$24 $(12) $593
quarterly $3
$(7)
performance despite
weather events and
market turbulence
$505
Other 1
3Q 2007 Adjusted Texas W est Southeast North SG&A, exc l. 3Q 2008 Adjusted
EBITDA deprec iation EBITDA
Texas Region – 62% ↑ Commodity Margin West Region – 10% ↓ Commodity Margin
Texas Region – 62% ↑ Commodity Margin West Region – 10% ↓ Commodity Margin
• Higher market spark spreads • Weather-driven, softer heat rates, and lower hedged prices
• Higher market spark spreads • Weather-driven, softer heat rates, and lower hedged prices
• Effective risk management following Hurricane Ike • Lower inventory value for NG storage
• Effective risk management following Hurricane Ike • Lower inventory value for NG storage
• Offset by lower steam sales due to Ike • Offset by favorable renegotiated contracts
• Offset by lower steam sales due to Ike • Offset by favorable renegotiated contracts
North Region – 22% ↑ Commodity Margin
Southeast Region – 5% ↓ Commodity Margin
North Region – 22% ↑ Commodity Margin
Southeast Region – 5% ↓ Commodity Margin
• Higher realized spark spreads
• Lower spark spreads on open positions
• Higher realized spark spreads
• Lower spark spreads on open positions
• Increased hedged position
• Auburndale deconsolidation and asset sales
• Increased hedged position
• Auburndale deconsolidation and asset sales
• Offset by deconsolidation of RockGen
• Offset by more hedging and new favorable PPA’s
• Offset by deconsolidation of RockGen
• Offset by more hedging and new favorable PPA’s
SG&A – $12 million Increase
SG&A – $12 million Increase
• Consulting and legal expenses
• Consulting and legal expenses
1 Includes the Other segment of commodity margin and cash realized mark-to-market. 23

25. YTD 2008 vs 2007 Adjusted EBITDA Bridge
Texas Region – 68% ↑ Commodity Margin
Texas Region – 68% ↑ Commodity Margin
• Higher spark spreads & effective risk management
• Higher spark spreads & effective risk management
• Transmission congestion in South and Houston zones
• Transmission congestion in South and Houston zones
$30 $(16) $(22)
$(56)
$79
West Region – 8% ↑ Commodity Margin
$1,361
West Region – 8% ↑ Commodity Margin
• Higher off-peak spark spreads in Q2
• Higher off-peak spark spreads in Q2
$265 • New favorable power contracts
• New favorable power contracts
Southeast Region – 9% ↑ Commodity Margin
Southeast Region – 9% ↑ Commodity Margin
• Higher hedged position; New favorable power contracts
• Higher hedged position; New favorable power contracts
• Sale of transmission capacity contract
• Sale of transmission capacity contract
$1,081
North Region – 6% ↑ Commodity Margin
North Region – 6% ↑ Commodity Margin
• Higher spark spreads offset by plant outages
• Higher spark spreads offset by plant outages
Other1
YTD 2007 Adjusted Texas West Southeast North SG&A, excl. YTD 2008 Adjusted
EBITDA depreciation EBITDA
SG&A – $22 million Increase
SG&A – $22 million Increase
• Consulting and legal expenses
• Consulting and legal expenses
Exceptional plant operations and commercial operations drive
Exceptional plant operations and commercial operations drive
YTD Adjusted EBITDA growth
YTD Adjusted EBITDA growth
1 Includes the Other segment of commodity margin and cash realized mark-to-market. 24

26. Liquidity and Debt Maturity
Liquidity Sensitivities to Collateral Requirements3:
($mm) 2Q08 3Q08
• $1/mmbtu Δ in NG prices $70-$80 mm inverse Δ in liquidity
Cash and Cash Equivalents, Corporate $157 $549
• .17mmbtu/MWh Δ in MHR $50-$55 mm inverse Δ in liquidity
Cash and Cash Equivalents, Non-corporate 213 302
Total Cash and Cash Equivalents $370 $851
NG = Natural Gas
MHR = Market Heat Rates
Revolver / LC Availability 1 306 739
2
Total Current Liquidity $676 $1,590
Debt Maturity Schedule 4
$5,621
85mm of PCFIII Notes
to be repaid from
Debt Maturity Assumptions:
existing restricted cash
• Excludes Letter of Credit facilities collateral account
• Maturity balances assume no cash
sweeps
• All other debt maturities are paid
off from operating cash flows at $1,628
the project level
$364
$185
2008 2009 2010 2011 2012 2013 2014
CCFC Project Debt First Lien Credit Facility
1 Includes total capacity under exit facility revolver, Calpine Development Holding, Inc. (CDHI) letter of credit facility, knock-in facility, and contingent
commodity revolver, less cash drawn and letters of credit outstanding as of such date.
2 Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the Commodity Collateral Revolver.
3 As of portfolio valuation on 10/31/2008
4 The schedule shown here is not prepared on a GAAP basis and does not conform to the debt maturity schedule presented in Calpine’s Form 10-Q. Refer to the
Form 10-Q for further information regarding GAAP-basis debt maturity.
25

27. Full Year 2008 Guidance
($mm) FY 2008 Recurring
Adjusted EBITDA $1,650 - $1,675
Major Cash Items
Recurring Cash Interest $800 $750
1
Cash Major Maintenance $165 $150 - $160
2
$260 - $290
million
Capital Expenditures $170 $110 - $130
3
Delivering on our commitment to increase the level of transparency
1 Recurring Cash Interest in 2008 excludes interest on Second Priority Senior Notes of approximately $250 million
2 2008 & 2009 higher than recurring amounts shown above
3 Purchases of property, plant, and equipment excludes major construction and development projects funded with debt
26

28. SUMMARY
27

29. Q&A
28

30. APPENDIX
29

31. Selected Operating Statistics 1
3Q08 3Q07 3Q08 3Q07
Total MWh Generated (in thousands) 25,868 27,127 Average MW of Peaker Facilities 2,540 3,019
West 10,563 10,218 West 983 983
Texas 9,830 9,907 Texas - -
Southeast 3,806 5,089 Southeast 963 963
North 1,669 1,913 North 594 1,073
Average Availability 96.6% 93.9% Average Capacity Factor, excl. Peakers 55.2% 54.6%
West 95.8% 94.2% West 73.9% 72.1%
Texas 96.9% 96.2% Texas 61.4% 61.8%
Southeast 97.4% 91.5% Southeast 29.8% 34.1%
North 96.7% 92.5% North 39.1% 39.0%
Average Total MW in Operation Steam Adjusted Heat Rate (Btu/KWh)
23,064 24,854 7,274 7,211
West 7,246 7,246 West 7,314 7,313
Texas 7,251 7,266 Texas 7,147 6,967
Southeast 6,205 7,327 Southeast 7,335 7,441
North 2,362 3,015 North 7,722 7,492
1 Excludes plants sold or mothballed since 3Q07 (Adjusted for sale of Acadia and mothball of Pryor). Not adjusted for deconsolidation of Auburndale and RockGen
30

32. Capital Structure Overview
3Q08
($mm)
Exit Credit Facility $ 5,935
Construction / Project Financing 2,008
CCFC Financing 777
Preferred Interests 335
Notes Payable and Other Borrowings 363
Capital Lease Obligations 277
Commodity Collateral Revolver 100
Total Debt $ 9,795
Less: Cash & Cash Equivalents 851
Net Debt $ 8,944
Net Debt //Adjusted EBITDA11 = 5.3x
Net Debt Adjusted EBITDA = 5.3x
1 Trailing twelve month Adjusted EBITDA as of September 30, 2008
31

33. Calpine Continues to Benefit from NOL Positions
• Calpine (including CCFC) has $5.3 billion of U.S. NOLs which will have
annual IRC Section 382 limitations on usage as follows:
- $4.8 billion over 14 years ($4.8 billion/14 years = $343 million/year)
- $465 million over 5 years ($465 million/5 years = $93 million/year)
- Any amount not utilized in any year from these limitations can be
carried forward to succeeding years.
• There are approximately $1.0 billion of NOLs associated with Canada.
• In addition to these NOLs, Calpine has significant deferred tax assets
related to the bankruptcy that will generate tax deductions not limited
under IRC Section 382.
• Calpine has identified an estimated $1.5 - $2.0 billion in total U.S. NOLs
generated during 2008, ~90% of which will not be limited under IRC Section
382.
32

34. Our Operating Portfolio:
Over 24,000 MW in 16 States and Canada
North Region
North Region
12 Plants
12 Plants
3,350 MW
3,350 MW
West Region
West Region
43 Plants
43 Plants
7,246 MW
7,246 MW
Southeast Region
Southeast Region
12 Plants
12 Plants
6,119 MW
6,119 MW
Texas Region
Texas Region
12 Plants
12 Plants
7,487 MW TOTAL
7,487 MW TOTAL
79 Plants
79 Plants
24,202 MW
24,202 MW
In Operation – Gas-Fired (62)
In Operation – Geothermal (17)
Note: Represents Calpine’s net ownership, including peaking capacity. As of October 17, 2008 33

35. Calpine Operating Plants – As of Oct. 17, 2008
With
Load CPN With Peaking
Technology Location COD Peaking
Type Interest Capacity, Net
Capacity
West Region
Agnews Power Plant* Natural Gas Intermediate CA 1990 28 100% 28
Blue Spruce Energy Center Natural Gas Peaking CO 2003 285 100% 285
Creed Energy Center Natural Gas Peaking CA 2003 47 100% 47
Delta Energy Center Natural Gas Intermediate CA 2002 840 100% 840
Feather River Energy Center Natural Gas Peaking CA 2002 47 100% 47
Geysers (17 plants) Geothermal Baseload CA 1971 - 1989 725 100% 725
Gilroy Cogeneration Plant* Natural Gas Intermediate CA 1998 128 100% 128
Gilroy Energy Center Natural Gas Peaking CA 2002 135 100% 135
Goose Haven Energy Center Natural Gas Peaking CA 2003 47 100% 47
Greenleaf 1 Power Plant* Natural Gas Intermediate CA 1989 50 100% 50
Greenleaf 2 Power Plant* Natural Gas Intermediate CA 1989 49 100% 49
Hermiston Power Project Natural Gas Intermediate OR 2002 616 100% 616
King City Cogeneration Plant* Natural Gas Intermediate CA 1989 120 100% 120
King City Peaking Energy Center Natural Gas Peaking CA 2002 45 100% 45
Lambie Energy Center Natural Gas Peaking CA 2003 47 100% 47
Los Esteros Critical Energy Facility Natural Gas Peaking CA 2003 188 100% 188
Los Medanos Energy Center* Natural Gas Intermediate CA 2001 540 100% 540
Metcalf Energy Center Natural Gas Intermediate CA 2005 605 100% 605
Pastoria Energy Center Natural Gas Intermediate CA 2005 750 100% 750
Pittsburg Power Plant* Natural Gas Intermediate CA 1965 64 100% 64
Riverview Energy Center Natural Gas Peaking CA 2003 47 100% 47
Rocky Mountain Energy Center Natural Gas Intermediate CO 2004 621 100% 621
South Point Energy Center Natural Gas Intermediate AZ 2001 520 100% 520
Sutter Energy Center Natural Gas Intermediate CA 2001 578 100% 578
Watsonville (Monterey) Cogen Plant* Natural Gas Intermediate CA 1990 29 100% 29
Wolfskill Energy Center Natural Gas Peaking CA 2003 48 100% 48
Yuba City Energy Center Natural Gas Peaking CA 2002 47 100% 47
Total - West Region 7,246
Texas Region
Baytown Energy Center* Natural Gas Intermediate TX 2002 830 100% 830
Brazos Valley Power Plant Natural Gas Intermediate TX 2003 594 100% 594
Channel Energy Center* Natural Gas Intermediate TX 2001 593 100% 593
Clear Lake Power Plant* Natural Gas Intermediate TX 1985 377 100% 377
Corpus Christi Energy Center* Natural Gas Intermediate TX 2002 505 100% 505
Deer Park Energy Center* Natural Gas Intermediate TX 2003 1,019 100% 1,019
Freeport Energy Center* Natural Gas Intermediate TX 2005 236 100% 236
Freestone Energy Center Natural Gas Intermediate TX 2002 1,036 100% 1,036
Hidalgo Energy Center Natural Gas Intermediate TX 2000 479 79% 376
Magic Valley Generation Station Natural Gas Intermediate TX 2002 692 100% 692
Pasadena Power Plant Natural Gas Intermediate TX 1998 776 100% 776
Texas City Power Plant* Natural Gas Intermediate TX 1987 453 100% 453
Total - Texas Region 7,487
34

36. Calpine Operating Plants (continued) – As of Oct. 17, 2008
With
Load CPN With Peaking
Technology Location COD Peaking
Type Interest Capacity, Net
Capacity
North Region
Bethpage Energy Center 3 Natural Gas Intermediate NY 2005 80 100% 80
Bethpage Peaker Natural Gas Peaking NY 2002 48 100% 48
Bethpage Power Plant Natural Gas Intermediate NY 1989 56 100% 56
Greenfield Energy Centre Natural Gas Intermediate Ontario, CA 2008 1,005 50% 503
Kennedy Int'l Airport Power Plant* Natural Gas Intermediate NY 1995 121 100% 121
Mankato Power Plant Natural Gas Intermediate MN 2005 324 100% 324
Riverside Energy Center Natural Gas Intermediate WI 2004 603 100% 603
RockGen Energy Center Natural Gas Peaking WI 2001 460 100% 460
Stony Brook Power Plant* Natural Gas Intermediate NY 1995 47 100% 47
Westbrook Energy Center Natural Gas Intermediate ME 2001 537 100% 537
Whitby Cogen Natural Gas Intermediate Ontario, CA 1998 50 50% 25
Zion Energy Center Natural Gas Peaking IL 2002 546 100% 546
Total - North Region 3,350
Southeast Region
Auburndale Peaking Energy Center Natural Gas Peaking FL 2002 116 100% 116
Auburndale Power Plant* Natural Gas Intermediate FL 1994 150 10% 15
Broad River Energy Center Natural Gas Peaking SC 2000 847 100% 847
Carville Energy Center* Natural Gas Intermediate LA 2003 501 100% 501
Columbia Energy Center* Natural Gas Intermediate SC 2002 606 100% 606
Decatur Energy Center Natural Gas Intermediate AL 2002 792 100% 792
Hog Bayou Energy Center Natural Gas Intermediate AL 2001 237 100% 237
Morgan Energy Center* Natural Gas Intermediate AL 2003 807 100% 807
Oneta Energy Center Natural Gas Intermediate OK 2002 1,134 100% 1,134
Osprey Energy Center Natural Gas Intermediate FL 2004 599 100% 599
Pine Bluff Energy Center* Natural Gas Intermediate AR 2001 215 100% 215
Santa Rosa Energy Center* Natural Gas Intermediate FL 2003 250 100% 250
Total - Southeast Region 6,119
TOTAL - CALPINE 24,202
* Indicates cogeneration plant
35

37. Reg G Reconciliation: Commodity Margin
Calpine uses the non-GAAP financial measure “Commodity Margin” to assess its financial performance on a consolidated basis and by its reportable segments.
Commodity Margin includes its electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and
expenses, and fuel and purchased energy expenses, but excludes mark-to-market activity and other service revenues. Calpine believes that Commodity Margin
is a useful tool for assessing the performance of its core operations and is a key operational measure reviewed by its chief operating decision maker.
Commodity Margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for Calpine’s results of
operations presented in accordance with GAAP. Commodity Margin does not purport to represent gross profit (loss), the most comparable GAAP measure, as an
indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.
Three Months Ended September 30, 2008
Consolidation
(in millions) And
West Texas Southeast North Other Elimination Total
Revenues from external customers $ 1,202 $ 1,354 $ 374 $ 208 $ 52 $ —$ 3,190
Intersegment revenues 11 89 74 2 4 (180) —
Total revenue $ 1,213 $ 1,443 $ 448 $ 210 $ 56 $ (180) $ 3,190
Commodity Margin $ 345 $ 272 $ 106 $ 96 $ 23 $ —$ 842
Add: Mark-to-market commodity
activity, net and other revenue(1) 7 52 1 1 (32) (3) 26
Less:
Plant operating expense 94 53 29 21 3 (2) 198
Depreciation and amortization expense 48 31 17 15 1 (2) 110
Other cost of revenue 14 — 4 7 1 — 26
Gross profit (loss) 196 240 57 54 (14) 1 534
Th ree Months Ended September 30, 2007
Consolidation
and
(in millions)
West Texas S outheast North Ot her Elimination T otal
Revenues from external customers $ 1,032 $ 784 $ 327 $ 186 $ (5) $ —$ 2,324
Intersegment revenues 7 1 41 6 2 (57) —
Total revenue $ 1,039 $ 785 $ 368 $ 192 $ (3) $ (57) $ 2,324
Commodity Margin $ 385 $ 168 $ 112 $ 79 $ (12) $ —$ 732
Add: Mark-to-market commodity
activity, net and other revenue (1) 1 37 1 — (15) (2) 22
Less:
Plant operating expense 81 44 29 21 10 (3) 182
Depreciation and amortization expense 52 31 18 14 1 (2) 114
Other cost of revenue 14 — 7 8 1 1 31
Gross profit (loss) 239 130 59 36 (39) 2 427
1 Included in operating revenues and fuel and purchased energy expenses.
36

38. Reg G Reconciliation: Commodity Margin (cont’d)
Nine Months Ended September 30, 2008
Consolidation
(in millions)
and
West Texas Southeast North Other Elimination Total
Revenues from external customers $ 3,320 $ 3,180 $ 1,031 $ 528 $ (90) $ —$ 7,969
Intersegment revenues 32 205 167 13 9 (426) —
Total revenue $ 3,352 $ 3,385 $ 1,198 $ 541 $ (81) $ (426) $ 7,969
Commodity Margin $ 954 $ 660 $ 234 $ 230 $ 35 $ —$ 2,113
Add: Mark-to-market commodity
activity, net and other revenue(1) 21 93 2 1 (187) (9) (79)
Less:
Plant operating expense 293 163 79 70 40 (9) 636
Depreciation and amortization expense 142 94 54 40 3 (4) 329
Other cost of revenue 44 — 20 19 5 — 88
Gross profit (loss) 496 496 83 102 (200) 4 981
Nine Months Ended September 30, 2007
Consolidation
(in millions) and
West Texas Southeast North Other Elimination Total
Revenues from external customers $ 2,636 $ 2,104 $ 828 $ 485 $ (7) $ —$ 6,046
Intersegment revenues 22 (1) 113 8 17 (159) —
Total revenue $ 2,658 $ 2,103 $ 941 $ 493 $ 10 $ (159) $ 6,046
Commodity Margin $ 880 $ 392 $ 214 $ 217 $ (14) $ —$ 1,689
Add: Mark-to-market commodity
activity, net and other revenue(1) 16 89 9 — (36) (18) 60
Less:
Plant operating expense 246 112 84 59 68 (8) 561
Depreciation and amortization expense 157 91 60 41 3 (2) 350
Other cost of revenue 36 — 23 25 22 (5) 101
Gross profit (loss) 457 278 56 92 (143) (3) 737
1 Included in operating revenues and fuel and purchased energy expenses.
37

39. Reg G Reconciliation: Adjusted EBITDA
Calpine uses the non-GAAP financial measure “Adjusted EBITDA” as a measure of its liquidity and performance. Calpine defines Adjusted EBITDA as EBITDA as
adjusted for certain items described in this presentation and in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance
with GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Adjusted EBITDA
does not purport to represent cash flow from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore,
Adjusted EBITDA is not necessarily comparable to similarly titled measures reported by other companies.
Calpine believes Adjusted EBITDA is used by and useful to investors and other users of our financial statements in analyzing our liquidity as it is the basis for
material covenants under our DIP Facility, which was our primary source of financing during our Chapter 11 cases, and under our Exit Facility, which is our
primary source of funding. Calpine also believes that EBITDA is widely used by investors to measure a company’s operating performance without regard to
items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting
methods and book value of assets, capital structure and the method by which assets were acquired.
(in millions) Three Months Ended September 30, Nine Months Ended September 30,
2008 2007 2008 2007
Cash provided by operating activities $ 941 $ 256 $ 355 $ 72
Less:
Changes in operating assets and liabilities 420 217 (12) 139
Additional adjustments to reconcile GAAP net
income to net cash provided by (used in) operating
activities:
Depreciation and amortization expense(1) 138 136 418 420
Deferred income taxes (145) 51 (60) 133
Panda settlement 13 — 13 —
Change in the fair value of derivative assets and
liabilities and derivative contracts classified as
financing activities 162 (14) (30) (24 )
Reorganization items (9) (3,956) (331) (3,459 )
Impairment charges 179 — 179 —
Loss on sale of assets, excluding reorganization
items — 22 6 24
Other 47 6 53 4
GAAP net income 136 3,794 119 2,835
Add:
Adjustments to reconcile GAAP net income to
Adjusted EBITDA:
Interest expense, net of interest income 201 603 799 1,133
Depreciation and amortization expense, excluding
deferred financing costs(1) 117 125 357 383
(Benefit) provision for income taxes (80) 51 (60) 133
Impairment charges 179 — 179 —
Loss on sale of assets, excluding reorganization
items — 22 6 24
Reorganization items (2) (3,940) (263) (3,366 )
Major maintenance expense 22 4 118 78
Losses on repurchase or extinguishment of debt — — 13 —
Operating lease expense 12 15 35 39
Gains on derivatives (non-cash portion) (38) (20) (10) (22 )
Claim settlement income — (129) — (129 )
Stock-based compensation expense (income) 17 — 36 (1 )
Other 29 (20) 32 (26 )
Adjusted EBITDA $ 593 $ 505 $ 1,361 $ 1,081
__________
38

40. Reg G Reconciliation: Adjusted EBITDA Guidance
Calpine uses the non-GAAP financial measure “Adjusted EBITDA” as a measure of its liquidity and performance. Calpine defines Adjusted EBITDA as EBITDA as
adjusted for certain items described in this presentation and in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance
with GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Adjusted EBITDA
does not purport to represent cash flow from operations or net income (loss) as defined by GAAP as an indicator of operating performance. Furthermore,
Adjusted EBITDA is not necessarily comparable to similarly titled measures reported by other companies.
Calpine believes Adjusted EBITDA is used by and useful to investors and other users of our financial statements in analyzing our liquidity as it is the basis for
material covenants under our DIP Facility, which was our primary source of financing during our Chapter 11 cases, and under our Exit Facility, which is our
primary source of funding. Calpine also believes that EBITDA is widely used by investors to measure a company’s operating performance without regard to
items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting
methods and book value of assets, capital structure and the method by which assets were acquired.
($mm) FY 2008 Range
Low High
Adjusted EBITDA $ 1,650 $ 1,675
Less:
1
Interest Expense, net of Interest Income 1,018 1,018
Operating Lease Expense 45 45
Depreciation and Amortization 442 442
Major Maintenance 175 175
2
Other (155) (155)
Net Income $ 125 $ 150
1 Includes interest paid on Second Priority Liens
2 Other includes Stock Compensation, Minority Interest Expense, Impairment, and other adjustments
39